Direct wrap measurement during connection for optimal slide drilling

ABSTRACT

A system or apparatus including: a controller configured to (i) deactivate and activate drilling fluid pump(s), (ii) provide operational control signals to connect tubular(s) to the tubular string, (iii) provide operational control signals to oscillate the connected tubular(s) and tubular string while the pump(s) are deactivated and activated, (iv) receive data, (v) determine a time at which motion is detected downhole, (vi) determine a number of oscillation revolutions of the tubular string required to affect toolface orientation based on the received toolface orientation data, and (vii) provide operational control signals to set a number of oscillation revolutions of the tubular string to less than the determined number; and a drive system configured to: (i) receive the operational control signals, and (ii) oscillate the connected tubular(s) and tubular string based on the set number of oscillation revolutions while maintaining a desired toolface orientation while slide drilling, and methods of providing and using the same for slide drilling.

BACKGROUND OF THE DISCLOSURE

Underground drilling involves drilling a bore through a formation deepin the Earth using a drill bit connected to a drill string. Two commondrilling methods, often used within the same hole, include rotarydrilling and slide drilling. Rotary drilling typically includes rotatingthe drilling string, including the drill bit at the end of the drillstring, and driving it forward through subterranean formations. Thisrotation often occurs via a top drive or other rotary drive means at thesurface, and as such, the entire drill string rotates to drive the bit.This is often used during straight runs, where the objective is toadvance the bit in a substantially straight direction through theformation.

Slide drilling is often used to steer the drill bit to effect a turn inthe drilling path. For example, slide drilling may employ a drillingmotor with a bent housing incorporated into the bottom-hole assembly(BHA) of the drill string. During typical slide drilling, the drillstring is not rotated and the drill bit is rotated exclusively by thedrilling motor. The bent housing steers the drill bit in the desireddirection as the drill string slides through the bore, therebyeffectuating directional drilling. Alternatively, the steerable systemcan be operated in a rotating mode in which the drill string is rotatedwhile the drilling motor is running.

A problem with conventional slide drilling arises when the drill stringis not rotated because much of the weight on the bit applied at thesurface is countered by the friction of the drill pipe on the walls ofthe wellbore. This becomes particularly pronounced during long lengthsof a horizontally drilled bore hole, which can cause the string tostick.

To reduce wellbore friction during slide drilling, a top drive may beused to oscillate or rotationally rock the drill string during slidedrilling to reduce drag of the drill string in the wellbore. Thisoscillation can reduce friction in the borehole. However, too muchoscillation can disrupt the direction of the drill bit by sending itoff-course during the slide drilling process, and too little oscillationcan minimize the benefits of the friction reduction, resulting in lowweight-on-bit and overly slow and inefficient slide drilling.

The parameters relating to the top-drive oscillation, such as the numberof oscillating rotations, are typically programmed into the top drivesystem by an operator, and may not be optimal for every drillingsituation. For example, the same number of oscillation revolutions maybe used regardless of whether the drill string is relatively long orrelatively short, and regardless of the sub-geological structure.Drilling operators, concerned about turning the bit off-course during anoscillation procedure, may under-utilize the oscillation features,limiting its effectiveness. Because of this, in some instances, anoptimal oscillation may not be achieved, resulting in relatively lessefficient drilling and potentially less bit progression.

Thus, a system that can determine and recommend an effective slidedrilling oscillation amount during a drilling process would be desirableand has been developed and described below. Thus, the present disclosureaddresses one or more of the problems of the prior art.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is a schematic of an apparatus according to one or more aspectsof the present disclosure.

FIG. 2 is a block diagram schematic of an apparatus according to one ormore aspects of the present disclosure.

FIG. 3 is a diagram according to one or more aspects of the presentdisclosure.

FIG. 4 is a flow chart of a method of slide drilling with a mud pulsetelemetry system according to one or more aspects of the presentdisclosure.

FIG. 5 is a flow chart of another method of slide drilling with a mudpulse telemetry system according to one or more aspects of the presentdisclosure.

FIG. 6 is a flow chart of a method of slide drilling with anelectromagnetic telemetry system according to one or more aspects of thepresent disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.Moreover, the formation of a first feature over or on a second featurein the description that follows may include embodiments in which thefirst and second features are formed in direct contact, and may alsoinclude embodiments in which additional features may be formedinterposing the first and second features, such that the first andsecond features may not be in direct contact.

This disclosure provides apparatuses, systems, and methods for improveddrilling efficiency by evaluating and determining an oscillation regimetarget, such as an oscillating revolution target, for a drillingassembly to reduce wellbore friction on a tubular string (e.g., oftenreferred to herein as a drill string) while not disrupting a bitalignment during a slide drilling process. The apparatuses, systems, andmethods allow a user (alternatively referred to herein as an “operator”)or a control system to determine a suitable number of revolutions(alternatively referred to herein as rotations or wraps) to oscillate atubular string in a manner that improves the drilling operation. Theterm drill string is generally meant to include any tubular string. Thisimprovement may manifest itself, for example, by increasing the slidedrilling speed, slide penetration rate, the usable lifetime ofcomponents, and/or other improvements. In one aspect, the system setsthe oscillation regime target, such as the target number of revolutionsused in slide drilling, based on parameters detected during rotarydrilling. These parameters may include, for example, vibration/motion,toolface orientation, and other parameters.

The disclosure provides a technique that can be performed using adrilling rig and a BHA where the mud pumps are stopped and later turnedback on, such as would normally happen during the connection of anadditional tubular or stand of drill pipe. The term drill pipe isexemplary and could refer to any type of tubular herein. The disclosedmethods allow for the quantitative measurement of how many actualoscillation revolutions of the drill pipe are required before thetoolface of the BHA is changed.

One of ordinary skill in the art understands that the number ofoscillation revolutions should be kept low to maintain the desiredposition of the toolface, but the number of oscillation revolutionsshould be high enough to break the friction along the length of thedrill string. Thus, finding the “correct” or optimum number ofoscillation revolutions is important for an effective drilling process.Advantageously, the methods provide for the direct measurement of howmuch oscillation can be provided before changing the toolface of the BHAto obtain the most benefit from the pipe oscillation during slidedrilling. In contrast to conventional oscillation methods, the methodsdescribed herein experimentally measure the number of oscillationrevolutions that are applied to a drill string before affecting thedirection of the BHA, instead of relying on models. Thus, instead of“guessing” what the oscillation regime target should be, the methodsdescribed herein actually determine a preferred oscillation regimetarget.

In one aspect, this disclosure is directed to apparatuses, systems, andmethods that optimize an oscillation regime target, such as the numberof revolutions of the tubular string, e.g., at the surface of theborehole, to provide more effective drilling. Drilling may be mosteffective when the drilling system oscillates the tubular stringsufficiently to rotate the string even very deep within the borehole,while permitting the drilling bit to rotate only under the power of themotor. For example, a revolution setting that rotates only the upperhalf of the string will be less effective at reducing drag than arevolution setting that rotates nearly the entire string. Therefore, anoptimal revolution setting may be one that rotates substantially theentire string without upsetting or rotating the BHA. Further, sinceexcessive oscillating revolutions during a slide might rotate BHA andundesirably change the drilling direction, the optimal angular settingwould not adversely affect the direction of drilling.

The apparatus and methods disclosed herein may be employed with any typeof directional drilling system using a rocking technique with anadjustable target number of revolutions, including handheld oscillatingdrills, casing running tools, tunnel boring equipment, mining equipment,and oilfield-based equipment such as those including top drives. Theapparatus is further discussed below in connection with oilfield-basedequipment, but the oscillation revolution selecting systems,apparatuses, and devices of this disclosure may have applicability to awide array of fields including those noted above.

Referring to FIG. 1, illustrated is a schematic view of an apparatus 100demonstrating one or more aspects of the present disclosure. Theapparatus 100 is or includes a land-based drilling rig. However, one ormore aspects of the present disclosure are applicable or readilyadaptable to any type of drilling rig, such as jack-up rigs,semisubmersibles, drill ships, coil tubing rigs, well service rigsadapted for drilling and/or re-entry operations, and casing drillingrigs, among others within the scope of the present disclosure.

The apparatus 100 includes a mast 105 supporting lifting gear above arig floor 110. The lifting gear includes a crown block 115 and atraveling block 120. The crown block 115 is coupled at or near the topof the mast 105, and the traveling block 120 hangs from the crown block115 by a drilling line 125. One end of the drilling line 125 extendsfrom the lifting gear to drawworks 130, which is configured to reel outand reel in the drilling line 125 to cause the traveling block 120 to belowered and raised relative to the rig floor 110. The other end of thedrilling line 125, known as a dead line anchor, is anchored to a fixedposition, possibly near the drawworks 130 or elsewhere on the rig.

A hook 135 is attached to the bottom of the traveling block 120. A topdrive 140 is suspended from the hook 135. A quill 145 extending from thetop drive 140 is attached to a saver sub 150, which is attached to adrill string 155 suspended within a wellbore 160. Alternatively, thequill 145 may be attached to the drill string 155 directly. It should beunderstood that other conventional drilling techniques for arranging arig do not require a drilling line, and these are included in the scopeof this disclosure. In another aspect (not shown), no quill is present.

The drill string 155 includes interconnected sections of drill pipe 165,a BHA 170, and a drill bit 175. The BHA 170 may include stabilizers,drill collars, and/or measurement-while-drilling (MWD) or wirelineconveyed instruments, among other components. The drill bit 175, isconnected to the bottom of the BHA 170 or is otherwise attached to thedrill string 155. One or more pumps 180 may deliver drilling fluid tothe drill string 155 through a hose or other conduit 185, which may befluidically and/or actually connected to the top drive 140.

As shown, the BHA 170 includes a telemetry system 172. The telemetrysystem 172 can be used to process signals from the MWD sensors andtransmit the data to the surface to a controller. In one embodiment, thetelemetry system 172 includes an electromagnetic (EM) telemetry system.EM telemetry involves the generation of electromagnetic waves whichtravel through the earth's surrounding formations from the wellbore,with detection of the waves at the surface. EM telemetry can betransmitted where there is no mud flowing through the drill string. Inanother embodiment, the telemetry system 172 includes a mud pulse (MP)telemetry system. MP telemetry involves creating pressure waves in thecirculating drilling mud in the drill string. Information acquired bythe downhole sensors is transmitted in specific time divisions bycreating a series of pressure waves in the mud column. This is achievedby changing the flow area and/or path of the drilling fluid as it passesthe BHA in a timed, coded sequence, thereby creating pressuredifferentials in the drilling fluid. MP telemetry systems require mud tobe flowing for telemetry to be transmitted.

In the exemplary embodiment depicted in FIG. 1, the top drive 140 isused to impart rotary motion to the drill string 155. However, aspectsof the present disclosure are also applicable or readily adaptable toimplementations utilizing other drive systems, such as a power swivel, arotary table, a coiled tubing unit, a downhole motor, and/or a rotaryrig, among others.

The apparatus 100 also includes a control system 190 configured tocontrol or assist in the control of one or more components of theapparatus 100. For example, the control system 190 may be configured totransmit operational control signals to the drawworks 130, the top drive140, the BHA 170 and/or the pump 180. The control system 190 may be astand-alone component installed near the mast 105 and/or othercomponents of the apparatus 100. In some embodiments, the control system190 is physically displaced at a location separate and apart from thedrilling rig.

FIG. 2 illustrates a block diagram of a portion of an apparatus 200according to one or more aspects of the present disclosure. FIG. 2 showsthe control system 190, the BHA 170 (not including the telemetry system172), and the top drive 140, identified as a drive system. The apparatus200 may be implemented within the environment and/or the apparatus shownin FIG. 1.

The control system 190 includes a user-interface 205 and a controller210. Depending on the embodiment, these may be discrete components thatare interconnected via wired or wireless means. Alternatively, theuser-interface 205 and the controller 210 may be integral components ofa single system.

The user-interface 205 may include an input mechanism 215 permitting auser to input a left oscillation revolution setting and a rightoscillation revolution setting. These settings control the number ofrevolutions of the drill string as the system controls the top drive orother drive system to oscillate the top portion of the drill string. Insome embodiments, the input mechanism 215 may be used to inputadditional drilling settings or parameters, such as acceleration,toolface set points, rotation settings, and other set points or inputdata. A user may input information relating to the drilling parametersof the drill string, such as BHA information or arrangement, drill pipesize, bit type, depth, formation information, among other parameters ordata. The input mechanism 215 may include a keypad, voice-recognitionapparatus, dial, button, switch, slide selector, toggle, joystick,mouse, data base and/or other available data input device. Such an inputmechanism 215 may support data input from local and/or remote locations.Alternatively, or additionally, the input mechanism 215, when included,may permit user-selection of predetermined profiles, algorithms, setpoint values or ranges, such as via one or more drop-down menus. Thedata may also or alternatively be selected by the controller 210 via theexecution of one or more database look-up procedures. In general, theinput mechanism 215 and/or other components within the scope of thepresent disclosure support operation and/or monitoring from stations onthe rig site as well as one or more remote locations with acommunications link to the system, network, local area network (LAN),wide area network (WAN), Internet, satellite-link, and/or radio, amongother means.

The user-interface 205 may also include a display 220 for visuallypresenting information to the user in textual, graphic, or video form.The display 220 may also be used, e.g., by the user, to input drillingparameters, limits, or set point data in conjunction with the inputmechanism 215. For example, the input mechanism 215 may be integral toor otherwise communicably coupled with the display 220.

In one example, the controller 210 may include a plurality of pre-storedselectable oscillation profiles that may be used to control the topdrive or other drive system. The pre-stored selectable profiles mayinclude a right rotational revolution value and a left rotationalrevolution value. The profile may include, in one example, 5.0 rotationsto the right and −3.3 rotations to the left. These values are typicallymeasured from a central or neutral rotation.

In addition to having a plurality of oscillation profiles, thecontroller 210 includes a memory with instructions for performing aprocess to select the profile. In some embodiments, the profile is asimply one of either a right (i.e., clockwise) revolution setting and aleft (i.e., counterclockwise) revolution setting. Accordingly, thecontroller 210 may include instructions and capability to select apre-established profile including, for example, a right rotation valueand a left rotation value. Because some rotational values may be moreeffective than others in particular drilling scenarios, the controller210 may be arranged to identify the rotational values that provide asuitable level, and generally an optimal level, of drilling speed. Thecontroller 210 may be arranged to receive data or information from theuser, the BHA 170, and/or the drive system 140 and process theinformation to select or put in place an oscillation profile that mightenable effective and efficient drilling.

The BHA 170 may include one or more sensors, typically a plurality ofsensors, located and configured about the BHA to detect parametersrelating to the drilling environment, the BHA condition and orientation,and other information. In the embodiment shown in FIG. 2, the BHA 170includes an MWD casing pressure sensor 230 that is configured to detectan annular pressure value or range at or near the MWD portion of the BHA170. The casing pressure data detected via the MWD casing pressuresensor 230 may be sent via electronic signal to the controller 210 viawired or wireless transmission.

The BHA 170 may also include an MWD shock/vibration sensor 235 that isconfigured to detect shock and/or vibration in the MWD portion of theBHA 170. The shock/vibration data detected via the MWD shock/vibrationsensor 235 may be sent via electronic signal to the controller 210 viawired or wireless transmission.

The BHA 170 may also include a mud motor ΔP sensor 240 that isconfigured to detect a pressure differential value or range across themud motor of the BHA 170. The pressure differential data detected viathe mud motor ΔP sensor 240 may be sent via electronic signal to thecontroller 210 via wired or wireless transmission. The mud motor ΔP maybe alternatively or additionally calculated, detected, or otherwisedetermined at the surface, such as by calculating the difference betweenthe surface standpipe pressure just off-bottom and pressure once the bittouches bottom and starts drilling and experiencing torque.

The BHA 170 may also include a magnetic toolface sensor 245 and agravity toolface sensor 250 that are cooperatively configured to detectthe current toolface. The magnetic toolface sensor 245 may be or includeany available (i.e., available used generally herein to refer to anycurrent or future-developed component) magnetic toolface sensor thatdetects toolface orientation relative to magnetic north or true north.The gravity toolface sensor 250 may be or include a gravity toolfacesensor which detects toolface orientation relative to the Earth'sgravitational field. In an exemplary embodiment, the magnetic toolfacesensor 245 may detect the current toolface when the end of the wellboreis less than about 7° from vertical, and the gravity toolface sensor 250may detect the current toolface when the end of the wellbore is greaterthan about 7° from vertical. However, other toolface sensors may also beutilized within the scope of the present disclosure that may be more orless precise or have the same degree of precision, includingnon-magnetic toolface sensors and non-gravitational inclination sensors.In any case, the toolface orientation detected via the one or moretoolface sensors (e.g., sensors 245 and/or 250) may be sent viaelectronic signal to the controller 210 via wired or wirelesstransmission.

The BHA 170 may also include an MWD torque sensor 255 that is configuredto detect a value or range of values for torque applied to the bit bythe motor(s) of the BHA 170. The torque data detected via the MWD torquesensor 255 may be sent via electronic signal to the controller 210 viawired or wireless transmission.

The BHA 170 may also include an MWD weight-on-bit (WOB) sensor 260 thatis configured to detect a value or range of values for WOB at or nearthe BHA 170. The WOB data detected via the MWD WOB sensor 260 may besent via electronic signal to the controller 210 via wired or wirelesstransmission.

The top drive 140 may also or alternatively may include one or moresensors or detectors that provide information that may be considered bythe controller 210 when it selects or sets the oscillation profile. Inthis embodiment, the top drive 140 includes a rotary torque sensor 265that is configured to detect a value or range of the reactive torsion ofthe quill 145 or drill string 155. The top drive 140 also includes aquill position sensor 270 that is configured to detect a value or rangeof the rotational position of the quill, such as relative to true northor another stationary reference. The rotary torque and quill positiondata detected via sensors 265 and 270, respectively, may be sent viaelectronic signal to the controller 210 via wired or wirelesstransmission.

The top drive 140 may also include a hook load sensor 275, a pumppressure sensor or gauge 280, a mechanical specific energy (MSE) sensor285, and a rotary RPM sensor 290.

The hook load sensor 275 detects the load on the hook 135 as it suspendsthe top drive 140 and the drill string 155. The hook load detected viathe hook load sensor 275 may be sent via electronic signal to thecontroller 210 via wired or wireless transmission.

The pump pressure sensor or gauge 280 is configured to detect thepressure of the pump providing mud or otherwise powering the BHA fromthe surface. The pump pressure detected by the pump sensor pressure orgauge 280 may be sent via electronic signal to the controller 210 viawired or wireless transmission.

The mechanical specific energy (MSE) sensor 285 is configured to detectthe MSE representing the amount of energy required per unit volume ofdrilled rock. In some embodiments, the MSE is not directly sensed, butis calculated based on sensed data at the controller 210 or othercontroller about the apparatus 100.

The rotary RPM sensor 290 is configured to detect the rotary RPM of thedrill string. This may be measured at the top drive or elsewhere, suchas at surface portion of the drill string. The RPM detected by the RPMsensor 290 may be sent via electronic signal to the controller 210 viawired or wireless transmission.

In FIG. 2, the top drive 140 also includes a controller 295 and/or othermeans for controlling the rotational position, speed and direction ofthe quill 145 or other drill string component coupled to the top drive140 (such as the quill 145 shown in FIG. 1). Depending on theembodiment, the controller 295 may be integral with or may form a partof the controller 210.

The controller 210 is configured to receive detected information (i.e.,measured or calculated) from the user-interface 205, the BHA 170, and/orthe top drive 140, and utilize such information to continuously,periodically, or otherwise operate to determine and identify anoscillation regime target, such as a target rotation parameter havingimproved effectiveness. The controller 210 may be further configured togenerate a control signal, such as via intelligent adaptive control, andprovide the control signal to the top drive 140 to set, adjust and/ormaintain the oscillation profile in order to most effectively perform adrilling operation.

Moreover, as in the exemplary embodiment depicted in FIG. 2, thecontroller 295 of the top drive 140 may be configured to generate andtransmit a signal to the controller 210. Consequently, the controller295 of the top drive 170 may be configured to influence the number ofrotations in an oscillation, the torque level threshold, or otheroscillation regime target. It should be understood the number ofrotations used at any point in the present disclosure may be a whole orfractional number.

FIG. 3 shows a portion of the display 220 that conveys informationrelating to the drilling process, the drilling rig apparatus 100, thedrive system 140, and/or the BHA 170 to a user, such as a rig operator.As can be seen, the display 220 includes a right oscillation amount at222, shown in this example as 5.0, and a left oscillation amount at 224,shown in this example as −3.0. These values represent the number ofrevolutions in each direction from a neutral center when oscillating. Inan exemplary embodiment, the oscillation revolution values are selectedto be values that provide a high level of oscillation so that a highpercentage of the drill string oscillates, to reduce axial friction onthe drill string from the bore wall, while not disrupting the directionof the BHA.

In this example, the display 220 also conveys information relating tothe torque settings that may be used as target torque settings to beused during an oscillation regime while slide drilling. Here, righttorque and left torque may be entered in the regions identified bynumerals 226 and 228 respectively.

In addition to showing the oscillation rotational or revolution valuesand target torque, the display 220 also includes a dial or target shapehaving a plurality of concentric nested rings. In this embodiment, themagnetic-based toolface orientation data is represented by the line 230and the data 232, and the gravity-based toolface orientation data isrepresented by symbols 234 and the data 236. The symbols and informationmay also or alternatively be distinguished from one another via color,size, flashing, flashing rate, shape, and/or other graphic means.

In the exemplary display 220 shown in FIG. 3, the display 220 includes ahistorical representation of the toolface measurements, such that themost recent measurement and a plurality of immediately priormeasurements are displayed. However, in other embodiments, the symbolsmay indicate only the most recent toolface and quill positionmeasurements.

The display 220 may also include a textual and/or other type ofindicator 248 displaying the current or most recent inclination of theremote end of the drill string. The display 220 may also include atextual and/or other type of indicator 250 displaying the current ormost recent azimuth orientation of the remote end of the drill string.Additional selectable buttons, icons, and information may be presentedto the user as indicated in the exemplary display 220. Additionaldetails that may be included or used, such as those disclosed in U.S.Pat. No. 8,528,663 to Boone, which is incorporated herein by expressreference thereto.

FIG. 4 is a flow chart showing an exemplary method 400 of slide drillingusing an MP telemetry system. The method begins at step 402, where thecontroller 210 turns off or deactivates the pumps 180 to stop the flowof drilling fluid. Once the pumps 180 are stopped, the controller atstep 404 instructs the drive system 140 to pull an additional stand ofpipe to connect to the drill string 155, and the drive system 140connects the stand to the drill string 155. Typically, at this point,after the stand is connected, the pumps 180 are turned back on and aftertelemetry data starts to be received, drilling is resumed.

In this method 400, however, rather than turning on the pumps 180 afterthe stand is connected, at step 406, the controller 210 instructs thedrive system 140 to oscillate or rock the drill string 155 by a smallamount for a few seconds until sufficient data is obtained. For example,the controller 210 may instruct the drive system 140 to oscillate thedrill string 155 one revolution clockwise (+1) and one revolutioncounterclockwise (−1) for about 10 seconds. At step 408, the controller210 starts or activates the pumps 180 to allow drilling fluid to onceagain flow through the drill string 155. After the vibration and/ormotion from the starting of pumps 180 is detected by the MWDshock/vibration sensor 235, the MP telemetry system 172 waits apreprogrammed transmit delay time (e.g., 60 seconds) before the MPtelemetry system 172 starts to transmit data to the surface. This canadvantageously permit the pump pressure to build before datatransmission begins. This data includes shock/vibration and motion datafrom MWD shock/vibration sensor 235, as well as toolface data frommagnetic toolface sensor 245 and gravity toolface sensor 250. At step410, the controller 210 receives the data and determines if the toolfacewas affected by the small amount of oscillation. In some embodiments,the controller 210 determines exactly when the toolface was affected.For example, the controller determines if motion was detected at thestart of the pumps 180 or earlier but during oscillation. The tooltypically will detect vibration either when the pumps 180 are activatedor when oscillation causes a toolface change.

At step 412, the controller 210 instructs the drive system 140 tooscillate the drill string 155 by a larger amount than the small amount.For example, the drive system can oscillate the drill string 155 tworevolutions clockwise (+2) and two revolutions counterclockwise (−2). Inother embodiments, the oscillation revolution amount may be 1.5 insteadof 2, or any other suitable amount in each direction. At step 414, thecontroller 210 receives data from MWD sensors 235, 245, and 250 todetermine if the toolface was affected by the larger amount ofoscillation. At step 416, the controller 210 increases (e.g., ramps up)the amount of oscillation in each direction until a change in toolfaceis detected.

At step 418, once the toolface is determined to be affected, thecontroller 210 determines the number of oscillation revolutions thatcaused the motion. This can be done, for example, by determining thetime that motion was detected, and determining how many oscillationrevolutions were applied at that time. At step 420, the controller 210establishes the pipe oscillation set point at a slightly lower levelthan the determined number of oscillation revolutions for slidedrilling. For example, if the number of oscillation revolutions thataffect the toolface of the BHA is determined to be 4, the pipeoscillation set point could be set at 3.5 or 3. This set point amountcan be a percentage of revolutions below the oscillation that causedtoolface orientation change (e.g., about 0.1, 0.2, 0.3, 0.4, 0.5, 1, 2,3, 4, 5, 10, 15, or 20 percent, etc.), a manually input set point, orthe previously tested set point at which the toolface orientation didnot change.

In various embodiments of this method 400, instead of slowly ramping upthe number of oscillation revolutions over time (e.g., 1, 2, 3, 4, 5,etc.), the controller 210 instructs the drive system 140 to slowly stepup the number of oscillation revolutions. For example, the drive system140 may oscillate the drill string 155 one (1) revolution for a certainamount of time (e.g., 10 seconds), then two (2) revolutions for acertain amount of time (e.g., 20 seconds), before turning on pumps 180.Once a preprogrammed transmit delay time has passed, the controller 210receives data from MP telemetry system 172, determines when motion wasdetected, and correlates the time with the number of oscillationrevolutions. Thus, this embodiment permits calculation of the totalnumber of wraps that occurred in the tubular string rather than simplydetecting the binary determination of whether the toolface was effectedor not.

FIG. 5 is a flow chart showing another exemplary method 500 of slidedrilling using an MP telemetry system. Steps 502-506 are similar tosteps 402-406 and step 508 is similar to step 408 discussed above withrespect to FIG. 4. An optional step 507 of stepping up or ramping up theoscillation amount, as described above for method 400, may be includedin method 500. In some embodiments of this method 500, the pumps 180 arenot started until the level of oscillation has reached a high enoughlevel to ensure that toolface has definitely been affected. Once thislevel of oscillation has been reached, the pumps 180 are turned on. Atstep 510, the controller 210 receives data from the MP telemetry system.In some embodiments, the data includes toolface orientation data,telemetry transmit delay times, or both. After the vibration/motion isdetected from the start of the pumps 180, the MP telemetry system 172waits the preprogrammed transmit delay time and then begins transmittingtelemetry data to the surface. This can advantageously ensure that theentire tubular string has been affected by the oscillation at thesurface and that sufficient mud flow from the pumps 180 is present forthe MP telemetry system 172 to properly transmit the data. At step 512,when the data begins to be transmitted to the surface, the preprogrammedtransmit delay time is subtracted from the time at which data began tobe received to calculate the time when the BHA 170 began to experiencemotion. At step 514, the controller 210 identifies whether the timecalculated in step 512 is before or after the activation of the pumps.At step 516, if the calculated time is before the pumps 180 areactivated, the controller 210 identifies the oscillation level from step506 or 507 that was being used at the calculated time. At step 518, thecontroller 210 establishes a pipe oscillation set point at a lower levelthan the determined number of oscillation revolutions that caused themotion. If the calculated time is after the activation of the pumps 180,the largest oscillation amounts from steps 506 and 507 are insufficientto cause motion of the BHA. At step 522, the controller 210 establishesa pipe oscillation set point at at least the largest oscillation amountfrom steps 506 and 507. At the next test opportunity, the controller 210can attempt a larger oscillation amount in step 506.

The methods 400 and 500 may be repeated for every new connection ofstand to the drill string 155, periodically for every n^(th) selectednumber of connections, when a change in the geologic conditions isotherwise detected as a result of changes in drilling operations, orwhen manually triggered by the user to double-check the optimaloscillation is being used. As the length of the drill string 155increases, its properties change and different oscillation targetregimes are needed. In some embodiments, different oscillation amountsare applied at every other or at each new connection to ensure a moreoptimal oscillation is used.

FIG. 6 is a flow chart showing an exemplary method 600 of slide drillingusing an EM telemetry system. The method begins at step 602, where thecontroller 210 turns off or deactivates the pumps 180 to stop the flowof drilling fluid. Once the pumps 180 are stopped, the controller atstep 604 instructs the drive system 140 to pull an additional stand ofpipe to connect to the drill string 155, and the drive system 140connects the stand to the drill string 155.

The EM telemetry system 172 starts transmitting data a certain amount oftime (e.g., 60 seconds) after the pumps 180 are turned off and beforethey are turned on again. This data typically includes shock/vibrationand motion data from MWD shock/vibration sensor 235, as well as toolfacedata from magnetic toolface sensor 245 and gravity toolface sensor 250.At step 606, the controller 210 receives this data from EM telemetrysystem 172. At step 608, the controller 210 instructs the drive system140 to oscillate or rock the drill string 155 by a small amount for afew seconds until sufficient data is obtained. Step 608 is similar tostep 406 above. At step 610, the controller 210 starts or activates thepumps 180 to allow drilling fluid to once again flow through the drillstring 155. At step 612, the controller 210 receives the data anddetermines if the toolface was affected by the small amount ofoscillation. Step 612 is similar to step 410 above. In some embodimentsstep 610 may be performed at some point after step 620 or 622 instead ofafter step 608.

At step 614, the controller 210 instructs the drive system 140 tooscillate the drill string 155 by a larger amount than the small amount.Step 614 is similar to step 412 above. At step 616, the controller 210receives data from MWD sensors 235, 245, and 250 to determine if thetoolface of the BHA was affected by the larger oscillation amount. Step616 is similar to step 414 above. At step 618, the controller 210increases (e.g., ramps up) the amount of oscillation until a change intoolface is detected.

At step 620, the controller 210 determines the oscillation level (ornumber of oscillation revolutions) that was running at the time thetoolface was affected. Step 620 is similar to step 418 above. In someembodiments, the EM telemetry system can be configured to transmit aparameter indicating a time delay after the telemetry started thatmotion was detected. This time delay can then be correlated with thenumber of oscillation revolutions that were applied at that time. Inother embodiments, the received toolface measurements from the tool canbe used directly to determine the time when the toolface is affected. Atstep 622, the controller 210 establishes the pipe oscillation set pointat a slightly lower level than the determined oscillation level forslide drilling. Step 622 is similar to step 420 above.

Like method 400, in various embodiments of this method 600, instead ofslowly ramping up the number of revolutions over time (e.g., 1, 2, 3, 4,5, etc.), the controller 210 instructs the drive system 140 to step upthe number of oscillation revolutions. Also like method 400, in someembodiments of this method 600, the pumps 180 are not started until thelevel of oscillation has reached a high enough level to ensure thattoolface has been affected. Once this level of oscillation has beenreached, the pumps 180 are turned on, and the controller 210 determinesthe oscillation level that affects the toolface of the BHA.

Like method 400, the method 600 is repeated for every new connection ofstand to the drill string 155, or based on an alternate plan asdisclosed above for method 400. In some embodiments, differentoscillation amounts can be tried at every other or at each newconnection.

As understood by one of ordinary skill in the art, variations of methods400, 500, and 600 can be performed based on the available sensors andtelemetry type of the BHA 170. For example, instead of the use of MP orEM telemetry systems, acoustic transmission through a drill string orelectronic transmission through a wireline or wired pipe may be used.

By using the systems and method described herein, a rig operator canmore easily operate the rig during slide drilling at a maximumefficiency to minimize the effects of frictional drag on the drillstring during slide drilling, while still providing low or minimal riskof rotating the BHA off-course during a slide. This can increasedrilling efficiency which saves time and reduces drilling costs.

According to a first aspect of the present disclosure, a systemincluding a controller and a drive system is provided. The controller isconfigured to: (i) deactivate and activate one or more pumps thatdeliver drilling fluid through a tubular string, (ii) provideoperational control signals to connect one or more tubulars to thetubular string, (iii) provide operational control signals to oscillatethe connected one or more tubulars and tubular string while the one ormore pumps are deactivated and activated, (iv) receive data from atelemetry system, (v) determine a number of oscillation revolutions ofthe tubular string required to affect toolface orientation based on thereceived telemetry data, and (vi) provide operational control signals toset a number of oscillation revolutions of the tubular string to lessthan the determined number of oscillation revolutions. The drive systemis configured to: (i) receive the operational control signals from thecontroller, and (ii) oscillate the connected one or more tubulars andtubular string based on the set number of oscillation revolutions sothat the connected one or more tubulars and tubular string oscillatewhile maintaining a desired toolface orientation while slide drilling.

According to a second aspect of the present disclosure, a method ofoscillating a tubular string while slide drilling is provided. Themethod includes deactivating and activating one or more pumps thatdeliver drilling fluid through a tubular string; instructing a drivesystem to connect one or more tubulars to the tubular string while theone or more pumps are deactivated; instructing the drive system tooscillate the connected one or more tubulars and tubular string whilethe one or more pumps are deactivated and activated; receiving, from atelemetry system, data; determining, based on the received data, whenthe toolface orientation data was affected by oscillation; correlating atime that the toolface orientation data was affected with a number ofoscillation revolutions applied by the drive system; and instructing thedrive system to oscillate the connected one or more tubulars and tubularstring at a number of oscillation revolutions less than the number ofoscillation revolutions that affected the toolface orientation data sothat the connected one or more tubulars and tubular string oscillatewhile maintaining desired toolface orientation while slide drilling.

According to a third aspect of the present disclosure, a non-transitorymachine-readable medium having stored thereon machine-readableinstructions executable to cause a machine to perform operations. Theoperations include deactivating and activating one or more pumps thatdeliver drilling fluid through a tubular string; instructing a top driveto connect one or more tubulars to the tubular string while the one ormore pumps are deactivated; instructing the top drive to oscillate theconnected one or more tubulars and tubular string a certain number ofoscillation revolutions while the one or more pumps are deactivated andactivated; instructing the top drive to oscillate the connected one ormore tubulars and tubular string a number of oscillation revolutionsgreater than the certain number of oscillation revolutions while the oneor more pumps are activated; receiving, from a telemetry system, datawhile the one or more pumps are activated; determining, based on thereceived data, how many oscillation revolutions are needed to affect thetoolface orientation data; and instructing the top drive to oscillatethe connected one or more tubulars and tubular string at a number ofoscillation revolutions less than the determined number of oscillationrevolutions so that the connected one or more tubulars and tubularstring oscillate while maintaining desired toolface orientation whileslide drilling.

Thus, various systems, apparatuses, methods, etc. have been describedherein. Although embodiments have been described with reference tospecific example embodiments, it will be evident that variousmodifications and changes may be made to these embodiments withoutdeparting from the broader spirit and scope of the system, apparatus,method, and any other embodiments described and/or claimed herein.Further, elements of different embodiments in the present disclosure maybe combined in various different manners to disclose additionalembodiments still within the scope of the present embodiments.Additionally, the specification and drawings are to be regarded in anillustrative rather than a restrictive sense.

The Abstract at the end of this disclosure is provided to comply with 37C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature ofthe technical disclosure. It is submitted with the understanding that itwill not be used to interpret or limit the scope or meaning of theclaims.

Moreover, it is the express intention of the applicant not to invoke 35U.S.C. § 112, paragraph 6 for any limitations of any of the claimsherein, except for those in which the claim expressly uses the word“means” together with an associated function.

What is claimed is:
 1. A system, comprising: a controller configured to:(i) deactivate and activate one or more pumps that deliver drillingfluid through a tubular string, (ii) provide operational control signalsto connect one or more tubulars to the tubular string, (iii) provideoperational control signals to oscillate the connected one or moretubulars and tubular string while the one or more pumps are deactivatedand activated, (iv) receive data from a telemetry system, (v) determinea number of oscillation revolutions of the tubular string required toaffect toolface orientation based on the received telemetry data, and(vi) provide operational control signals to set a number of oscillationrevolutions of the tubular string to less than the determined number ofoscillation revolutions; and a drive system configured to: (i) receivethe operational control signals from the controller, and (ii) oscillatethe connected one or more tubulars and tubular string based on the setnumber of oscillation revolutions so that the connected one or moretubulars and tubular string oscillate while maintaining a desiredtoolface orientation while slide drilling.
 2. The system of claim 1,wherein the operational control signals to oscillate the connected oneor more tubulars and tubular string while the one or more pumps areactivated comprise signals to increase a number of oscillationrevolutions over time.
 3. The system of claim 1, wherein the controlleris further configured to repeat steps (i)-(vi) and the drive system isfurther configured to repeat steps (i) and (ii) for a majority of theconnections of a plurality of connected tubulars to the tubular string.4. The system of claim 1, wherein the telemetry system comprises a mudpulse telemetry system.
 5. The system of claim 4, wherein the mud pulsetelemetry system is configured to wait a preprogrammed transmit delaytime before transmitting telemetry data to the controller.
 6. The systemof claim 5, wherein the controller is further configured to: determine atime that the toolface orientation data was affected or at which abottom hole assembly (BHA) begins to experience vibration; and subtractthe preprogrammed transmit delay time from the time that the toolfaceorientation data was affected or from the time at which the BHAbegins toexperience vibration.
 7. The system of claim 1, wherein the telemetrysystem comprises an electromagnetic telemetry system.
 8. The system ofclaim 7, wherein the electromagnetic telemetry system is configured totransmit toolface orientation data before the one or more pumps areactivated.
 9. The system of claim 1, wherein the received telemetry datacomprises a parameter indicating a time delay before or after a start oftransmission of data that toolface orientation data was affected,toolface orientation data, or both
 10. The system of claim 1, whereinthe received telemetry data comprises a parameter indicating a timedelay relative to a stop of a prior transmission.
 11. A method ofoscillating a tubular string while slide drilling, which comprises:deactivating and activating one or more pumps that deliver drillingfluid through a tubular string; instructing a drive system to connectone or more tubulars to the tubular string while the one or more pumpsare deactivated; instructing the drive system to oscillate the connectedone or more tubulars and tubular string while the one or more pumps aredeactivated and activated; receiving, from a telemetry system, data;determining, based on the received data, when the toolface orientationdata was affected by oscillation; correlating a time that the toolfaceorientation data was affected with a number of oscillation revolutionsapplied by the drive system; and instructing the drive system tooscillate the connected one or more tubulars and tubular string at anumber of oscillation revolutions less than the number of oscillationrevolutions that affected the toolface orientation data so that theconnected one or more tubulars and tubular string oscillate whilemaintaining desired toolface orientation while slide drilling.
 12. Themethod of claim 11, wherein instructing the drive system to oscillatethe connected one or more tubulars and tubular string while the one ormore pumps are activated comprise instructing the drive string to rampup or step up oscillation over time.
 13. The method of claim 11, whereinreceiving data from a telemetry system comprises receiving delayed datafrom a mud pulse telemetry system.
 14. The method of claim 13, furthercomprising subtracting a preprogrammed transmit delay time from the timethat the data was affected or from the time at which a bottom holeassembly (BHA) begins to experience vibration.
 15. The method of claim11, wherein receiving data from a telemetry system comprises receivingtoolface orientation data from an electromagnetic telemetry system whilethe one or more pumps are deactivated.
 16. The method of claim 11,wherein receiving data from a telemetry system comprises receiving aparameter indicating a time delay after a start of transmission of datathat toolface orientation data was affected, toolface orientation data,or both.
 17. A non-transitory machine-readable medium having storedthereon machine-readable instructions executable to cause a machine toperform operations that, when executed, comprise: deactivating andactivating one or more pumps that deliver drilling fluid through atubular string; instructing a top drive to connect one or more tubularsto the tubular string while the one or more pumps are deactivated;instructing the top drive to oscillate the connected one or moretubulars and tubular string a certain number of oscillation revolutionswhile the one or more pumps are deactivated and activated; instructingthe top drive to oscillate the connected one or more tubulars andtubular string a number of oscillation revolutions greater than thecertain number of oscillation revolutions while the one or more pumpsare activated; receiving, from a telemetry system, data while the one ormore pumps are activated; determining, based on the received data, howmany oscillation revolutions are needed to affect the toolfaceorientation data; and instructing the top drive to oscillate theconnected one or more tubulars and tubular string at a number ofoscillation revolutions less than the determined number of oscillationrevolutions so that the connected one or more tubulars and tubularstring oscillate while maintaining desired toolface orientation whileslide drilling.
 18. The non-transitory machine-readable medium of claim17, wherein receiving data from a telemetry system while the one or morepumps are activated comprises receiving delayed toolface orientationdata from a mud pulse telemetry system.
 19. The non-transitorymachine-readable medium of claim 18, wherein the operations furthercomprise: determining a time that the toolface orientation data wasaffected; or at which a bottom hole assembly (BHA) begins to experiencevibration; and subtracting a preprogrammed transmit delay time from thetime that the toolface orientation data was affected or from the time atwhich the BHA begins to experience vibration.
 20. The non-transitorymachine-readable medium of claim 17, wherein the operations furthercomprise receiving data from a telemetry system while the one or morepumps are deactivated.
 21. The non-transitory machine-readable medium ofclaim 20, wherein receiving data from a telemetry system while the oneor more pumps are deactivated comprises receiving toolface orientationdata from an electromagnetic telemetry system.